Sunday, July 20, 2014

Explorers 2014: Repsol feeling ‘positive’ about Alaska exploration

Eric Lidji
For Petroleum News

Having completed its initial three-season exploration program the Spanish major is eying development

Repsol E&P USA Inc. recently finished its most important season in Alaska to date.

After announcing three discoveries last year, the Spanish major completed a three-well program this winter - a pair of appraisal wells in the Colville River Delta and an exploration well south of the Prudhoe Bay and Kuparuk River units. Those wells “finished with positive results,” Chief Financial Officer Miguel Martinez said at a first quarter earnings call on May 12. “We are working toward defining the most economical way to develop the area,” he added, saying it was too soon to comment further.

With the two appraisal wells, Repsol attempted to alleviate uncertainties around the earlier discoveries with the goal of sanctioning a major development, Repsol Alaska Project Manager Bill Hardham told the Alaska Support Industry Alliance on Jan. 23.

While declining to offer a timeline for development, Hardham said, “I feel confident it’s coming. It’s not a matter of if, but when.” But Hardham also warned, “The predictability of the regulations and tax structure is key to making these big investment decisions.”

It’s certainly no surprise to hear an oil company advocate for low and stable taxes over high and shifting taxes, and Repsol has never given a straightforward ultimatum about what might happen if voters overturn the new fiscal system in a referendum this summer, but Hardham listed taxation alongside geophysical analysis and stakeholder engagement as the major “uncertainties” Repsol must resolve before it could sanction development.

To the west, to oil

Repsol started as a state-owned monopoly created before the Spanish Civil War, but reorganized over the following decades and became a private company in the late 1980s.

Repsol was primarily a European downstream company before it acquired the Argentinean company YPF in 1999 and created the multinational Repsol YPF S.A. After that, the company began rapidly expanding, particularly across Latin America.

Today, Repsol maintains assets in more than 50 countries around the world.

The growth made Repsol a major player, but over the past decade the company decided to take a different approach by focusing on the West and on increasing its oil production.

With its portfolio weighted toward South America and Africa, Repsol decided to grow its presence in developed economies. In a four-year plan announced in early 2008, the company set a goal to have at least 55 percent of its assets in OECD countries by 2012.

Global events subsequently supported the move. Repsol temporarily lost its largest source of production during the recent uprising in Libya. The company cancelled plans for a $10 billion investment in an Iranian natural gas venture because of the threat of sanctions over the Iranian nuclear program. Argentina essentially nationalized the YPF portion of the company, and several other South American countries changed their fiscal terms.

The strategic plan also favored oil production

Over the 2000s, Repsol had invested heavily in liquefied natural gas, becoming the third largest LNG company in the world. Of the 2 billion barrels of oil equivalent in total reserves the company reported in 2009, only 890 million barrels came from oil.

With import terminals in Spain and eastern Canada, and export terminals in Trinidad and Tobago and Peru, Repsol’s LNG assets were focused in the Atlantic Ocean, where there was talk of surpluses. By placing a priority on oil in its strategic plan, Repsol could diversify its portfolio and take advantage of the historic, decade-long rise in oil prices.

First steps north

This strategic plan is why Repsol first dipped its toe in Alaska waters. It started in 2007, when Repsol partnered with Shell and Eni on a block of federal leases in the Beaufort Sea. (Shell operated the joint venture.) Repsol said “exploration activities” could begin as early as 2009-10, but lawsuits delayed any activities.

At the time, Repsol stayed quiet about its larger intentions in Alaska, which allowed rumors to swirl. Given the outreach efforts of the Palin administration, some thought Repsol might invest in a North Slope natural gas pipeline under the Alaska Gasline Inducement Act, which had recently become law and was then accepting applications.

Ultimately, Repsol did not submit an AGIA application, but the company still invested in Alaska. In early 2008, Repsol bid $15.6 million on 104 tracts in the record-breaking federal lease sale in the Chukchi Sea, including $14.4 million in high bids on 93 tracts.

The leases were clustered into three groups. The first was north of the Popcorn well that Shell drilled in 1990. The second was between the Popcorn well and the Burger well to the east. The third was to the north, in a region thought to contain Brookian potential.

A big joint venture

Even with those bold moves into the Arctic, Hardham insisted that Repsol remained cautious about the state, saying that the company “turned down several opportunities to come in further into Alaska, largely because of the uncompetitive tax structure.” In March 2011, though, Repsol acquired a 70 percent working interest in North Slope leases held by the Armstrong Oil & Gas subsidiary 70 & 148 LLC and its fellow Denver-based independent GMT Exploration LLC. The joint venture covered 494,211 acres in the White Hills region south of the Kuparuk River unit and near the Oooguruk unit.

The $768 million deal earmarked some $750 million for exploration, according to Petroleum News sources, suggesting that all three parties wanted to get to development.

Why was Repsol skeptical about Alaska in 2009 but ready to invest heavily in 2011? It was a combination of the right opportunity and the winds of change, according to Hardham. “Repsol felt that this was the right time, things were changing, it was a good opportunity - they don’t come along very often. It fit with the strategy,” he said.

Less than a month before announcing the deal, Armstrong Vice President Ed Kerr had submitted a letter to state lawmakers in favor of House Bill 110, which was the legislative vehicle under discussion at the time for changing the fiscal system for oil production.

“The improved fiscal terms as proposed by HB 110, particularly the portions of the bill that apply to activities outside of existing units, will give us the needed incentive to not only drill multiple new wildcat and delineation wells, but the motivation to drive certain projects to development,” Kerr wrote, saying his company had “more than a dozen ideas outside of existing producing units” that it was eager to explore in the coming years.

What about gas?

Alaska provided a unique opportunity for Repsol.

“This deal is a perfect fit in our efforts to balance our exploration portfolio with lower risk, onshore oil opportunities in a stable environment. We are confident that our worldwide experience combined with a partner with an extensive local knowledge is going to deliver value in the near future,” Chairman Antonio Brufau said at the time.

As a politically low-risk onshore oil opportunity, the Alaska leases offset Repsol’s large liquefied natural gas trade and also its exploration in prolific but technically challenging oil-rich basins such as the deepwater Gulf of Mexico and the Santos basin off Brazil.

Even so, some still wondered whether Repsol might also be interested in natural gas.

Chevron drilled five shallow wells across the White Hills region in 2008 and 2009. The company never released well results, but the state of Alaska believed the region to be both oil and gas prone, and Alaska Oil and Gas Conservation Commission well logs suggested Chevron was targeting oil and natural gas prospects in the Brookian formation.

A poster child

Just as Pioneer Natural Resources Alaska Inc. became a poster child during debates over Alaska’s Clear and Equitable Share in 2007, Repsol E&P USA is getting stuck in a tug-of-war over the More Alaska Production Act, which replaced the ACES system last year. The debates over ACES often featured Pioneer Natural Resources.

The large independent operated under three tax systems during the five years it took to reach first oil at its Oooguruk unit, but also earned considerable tax credits in the process.

While much bigger than Pioneer, Repsol also falls in the middle of the spectrum for international oil companies. It is smaller than Shell, Exxon, BP, ConocoPhillips or even Eni, but much larger than the smaller independents working on the North Slope, like Brooks Range Petroleum Corp. or Savant Alaska LLC. As such, some consider it a bellwether: if Repsol wants to invest in Alaska, the investment climate must be good.

When Repsol arrived on the North Slope in March 2011, the company promised to spend it initial exploration budget over “several years.” Lawmakers such as Sen. Bill Wielechowski, an Anchorage Democrat, believed that the deal vindicated ACES, which expanded tax credits for exploration but also increased the tax rate when oil prices rise.

To some, the deal suggested that even with higher taxes, the developed world might be more attractive because of its lower political risks. “They want to enlarge their portfolio (in areas) that are politically stable,” Rep. Paul Seaton, a Homer Republican, told Petroleum News in March 2011. “Even as we, Norway and other countries have higher tax rates than some Third World countries, the political stability is very beneficial.”

Those comments came as lawmakers were beginning to debate changes to ACES. By the time Repsol announced its discoveries in early 2013, those changes had become the law.

Did SB 21 help?

In announcing the discoveries, Repsol called the recent tax changes “a critical factor in ensuring the development of this project,” a claim that Gov. Sean Parnell proudly touted.

“Can you say they made this investment because of the tax change?” House Speaker Mike Chenault, a Kenai Republican, told Petroleum News in May 2013, referring to Repsol. “I don’t know if you can really say that, but it’s going in the right direction. We are hearing about projects that have a chance of coming online versus where they were pulling projects off the board because they didn’t make economic sense under ACES.”

As the passage of Senate Bill 21 prompted a voter referendum to repeal it, Rep. Les Gara, an Anchorage Democrat, questioned drawing any link to the development plans. “Repsol announced two years ago they were going to invest at least three quarters of a billion dollars in Alaska, and if they found oil, more than that,” he told Petroleum News in August 2013. “Well they found oil in the spring and the governor said, hey this is because of SB 21. Folks who are going to try to stop the referendum will say anything they can.”

Today, Repsol claims that its decision to invest so heavily in Alaska in early 2011 was more of an informed risk than vote of confidence. “It was really about timing. … If you wait too long you can’t get the opportunity,” Hardham said. “So Repsol took a bit of a risk. They saw that there was change afoot. There was an opportunity, so we came.”

According to Hardham, Repsol believes the current system brings Alaska closer to the Lower 48, where it maintains operations in the Gulf of Mexico and in the Midcontinent.

“If you’re not competitive it gets really tough to develop these projects,” he said.

The Qugruk unit

The Repsol leasehold is spread across three chunks of the central North Slope.

The first is a T-shaped bundle running up the fairway between the Kuparuk River and Colville River units and spreading along the state waters of the Beaufort Sea. The second is a diagonal swath running south from Kuparuk nearly to the Brooks Range. The third is a smaller bundle hugging a bend in the Colville River south of the village of Nuiqsut.

In October 2011, Repsol and its partners applied to form the 98,852-acre Qugruk unit over 49 leases in the T-shaped bundle and proposed a four-well plan of exploration.

The region had been home to considerable exploration in previous decades, including six wells within the proposed unit boundaries going back to 1966 as well as 2-D and 3-D seismic, according to Repsol. The company described the primary objectives for the proposed unit as “sands within the upper portion of the Jurassic Kingak Shale, the Cretaceous Kup ‘C’ sand and several sands within the Cretaceous Nanushuk Group.”

In January 2012, the Alaska Department of Natural Resources approved a 12,065-acre unit over six leases just east of the Colville River unit, required Repsol to post a $20 million bond that would be returned if the company completed the Qugruk No. 4 well by June 30, 2012, and increased the rental rates on four leases set to expire in August 2012.

The smaller unit, the large bond and the relatively quick drilling commitment was meant to protect the state. The state felt that Repsol had “identified numerous high quality prospective targets over a large area in multiple stratigraphic intervals which will need to be drilled in order to prove up, which they propose to do in part during the proposed initial unit plan,” but also believed that unitization was “not technically supported.”

In mid-2013, Repsol asked the state to extend the primary terms of five un-unitized leases in the Qugruk area by three or four years. The request came after lawmakers passed House Bill 198, which gave state regulators additional authority to extend lease terms.

The law was designed to accommodate exploration companies that had spent considerable time and money exploring, but needed additional time to bring leases into production. Repsol had spent some $200 million exploring the leases since 2011, according to estimates from the company and the Department of Natural Resources.

The state ultimately gave Repsol an additional two years on the leases, but required the company to drill an additional well, post a $100,000 bond and collect new seismic. The decision made Repsol the first company to benefit from the law.

A three-year program

Repsol initially planned a five-well program for early 2012, but narrowed its efforts to four wells to alleviate local concerns. Those wells were the Qugruk No. 1, Qugruk No. 2 and Qugruk No. 4 along the Colville River Delta and just offshore and the Kachemach No. 1 much further south, near the Meltwater satellite of the Kuparuk River unit.

For the work, the company built 48 miles of ice roads in two segments. The first started at the Kuparuk River unit Drill Site 3S (or Palm satellite) and ran over the frozen coastal waters of the Beaufort. The other ran south from Drill Site 2S (or Meltwater satellite).

After a blowout at the Qugruk No. 2 well delayed its operations for several weeks, Repsol was only able to complete two wells: Qugruk No. 4 and Kachemach No. 1.

For early 2013, Repsol planned a three well program. Those wells were a second attempt at Qugruk No. 1, a Qugruk No. 2 re-drill called Qugruk No. 6 and Qugruk No. 3.

The company built an ice airstrip near Kuparuk Drill Site 2M and 38 miles of ice roads snaking north to Qugruk No. 1 and Qugruk No. 6 and south to Qugruk No. 3.

All three wells encountered hydrocarbons. Repsol performed drill stem tests on Qugruk No. 1 and Qugruk No. 6 and performed some early geotechnical work for development.

This winter, Repsol appraised those earlier discoveries with the Qugruk No. 5 and Qugruk No. 7 wells. Repsol also built a four-mile ice road south from Kuparuk to drill the Tuttu No. 1 exploration well on a lease just south of Prudhoe Bay and Kuparuk.

To bolster those activities, Repsol also contracted two 3-D seismic surveys. SAE Exploration conducted the Niglik Fiord survey covering some 222.39 square miles just offshore of the Colville River Delta, including the Repsol-operated Qugruk unit.

And Global Geophysical Services conducted the Schrader Bluff survey covering some 293.45 square miles south of Prudhoe and Kuparuk, including the Tuttu No. 1 well.

Read more:

Clock stopped for Shell in Chukchi Sea

By Tim Bradner
Alaska Journal of Commerce

Shell’s Arctic Challenger oil containment barge at the Port of Bellingham International Dock in Bellingham, Wash., seen in February 2013. Shell did not continue its plans for Arctic drilling in 2013 and 2014. The clock is still ticking on the company’s leases in the Beaufort Sea, although the Chukchi leases are on hold.

Shell’s Arctic Challenger oil containment barge at the Port of Bellingham International Dock in Bellingham, Wash., seen in February 2013. Shell did not continue its plans for Arctic drilling in 2013 and 2014. The clock is still ticking on the company’s leases in the Beaufort Sea, although the Chukchi leases are on hold.

The clock is ticking on Shell’s Outer Continental Shelf leases in Alaska’s Beaufort Sea. A large number of the company’s leases are set to expire in October 2017, federal officials said, although the leases on Shell’s two top prospects, Sivulliq and Torpedo, have been extended to July and October 2019.

Meanwhile, the U.S. Bureau of Ocean Energy Management, or BOEM, has stopped the clock on federal offshore leases held by Shell, ConocoPhillips and Statoil in the Chukchi Sea due to an ongoing lawsuit.

The Chukchi Sea has been Shell’s top priority in the Alaska OCS since 2013. ConocoPhillips and Statoil only have leases in the Chukchi Sea, and not the Beaufort Sea.

Shell drilled two partially-complete exploration wells in 2012, one in the Chukchi Sea and one in the Beaufort Sea, and had planned to return to both exploration areas in 2013 until the specialized drilling vessel Shell used in the Beaufort, the Kulluk, was damaged in a grounding near Kodiak in December 2012.

The Kulluk had been designed for Beaufort Sea conditions and had been given air quality permits by the U.S. Environmental Protection Agency. Partly because it lacked a suitable vessel that had its permits, Shell put the Beaufort Sea on the back-burner for its proposed 2013 drilling, and focused on the Chukchi Sea. The company was unable to return to the Chukchi for the 2013 and 2014 open-water drilling seasons because of pending new federal regulations on drilling.

OCS leases have 10-year terms and the Chukchi Sea sale was in 2008, but the lease clock for all three companies with leases in the Chukchi has been frozen until BOEM completes a supplementary environmental impact statement, or SEIS, for the 2008 Chukchi Sea OCS Sale 193, according to U.S. Bureau of Ocean Energy Management officials.

The revamp of the original environmental impact statement for the sale was challenged in court by environmental groups who argued the assumed size of a discovery, and the size of a possible oil spill, were underestimated in 2008 by the U.S. Minerals Management Service, the predecessor agency to BOEM.

The agency is now redoing the estimates. A draft SEIS is expected this fall and a final document by next March, BOEM has said.

“All of the Chukchi Sea leases, including the (Shell) Burger prospect, were put into suspended status. This status will remain in effect until the Bureau meets its obligations to correct the Sale 193 EIS consistent with the U.S. Ninth Circuit’s opinion and the direction of the (federal) district court,” said a BOEM official, who asked not to be identified because of agency procedures.

The revamp of the 2008 EIS, the more recent development, was ordered by a U.S. District Court judge in Anchorage after the U.S. Ninth Circuit Court of Appeals agreed with the environmental plaintiffs.

The U.S. Mineral Management Service had originally used an assumption that a 1 billion-barrel discovery could be made in the Chukchi, and further assumptions on a possible oil spill were based on that. Environmental groups said the figure was too low, and that the assumptions for the oil spill were also too low.

With the standard 10-year term leases sold in Sale 193 would have expired in August 2019. The new expiration date is unknown and will not be established until the SEIS is issued and approved, the BOEM official said.

The delay in drilling Shell’s top prospects in the Beaufort Sea has implications for Alaska. Oil from any discoveries in the Beaufort could be brought ashore to bolster Trans-Alaska Pipeline System, or TAPS, oil “throughput” much more quickly than oil from any Chukchi Sea discoveries.

The Sivulliq and Torpedo offshore prospects are in the eastern Alaskan Beaufort Sea about 15 miles north of the Point Thomson onshore oil and gas development east of Prudhoe Bay. A pipeline to shore could be built more quickly than a 60-mile Chukchi Sea pipeline to shore, and once ashore the Beaufort Sea oil could be shipped to TAPS through the existing Point Thomson and Badami liquids pipeline.

Chukchi Sea oil, once ashore, would still require a new pipeline across the National Petroleum Reserve-Alaska to the TAPS line.

It would take more than a decade for Chukchi Sea oil, once drilled and discovered, to be brought into TAPS, state officials have said. Beaufort Sea oil, once discovered, could possibly be brought to TAPS in about half the time, they said.

Getting more oil into TAPS is important because TAPS throughput has been declining to the point that there could be operating problems during very cold winter conditions. More oil volumes, no matter from what source, will ease these.

Also, although OCS oil pays no royalty or production tax to the state of Alaska it indirectly increases state revenue because the higher volumes in TAPS lowers the pipeline’s per-barrel tariff for shipping oil. Since that applies to all oil shipped in the pipeline it results in a higher value of oil from state leases on the North Slope, resulting in higher royalties and production tax payments.

Read More:

Fairbanks legislator suggests Interior gas pilot project

Elwood Brermer
Alaska Journal of Commerce

A Fairbanks legislator is pushing state officials to market the benefits of converting home heating systems away from fuel oil to Interior residents.

Rep. David Guttenberg said representatives from the Alaska Industrial Development and Export Authority and its sister group the Alaska Energy Authority involved in the Interior Energy Project have expressed concerns over the prospect of a market for North Slope gas in the Fairbanks area at recent meetings.

The Interior Energy Project is the state’s plan to truck liquefied North Slope natural gas to Fairbanks and North Pole as a way to relieve high energy costs and poor winter air quality caused by the region’s dependence on home heating oil.

“It’s the same old dialogue about there’s no gas because there’s no market — no market because there’s no gas,” Guttenberg said in an interview with the Journal.

Fairbanks Natural Gas, which already supplies more than 1,100 customers in the core of Fairbanks with natural gas, and the Interior Gas Utility, or IGU, estimate they will combine to make gas available to about 13,600 new residential customers by 2024. With a much larger distribution build out plan, IGU will be able to supply less than 2,000 residences when first gas is available in late 2016, according to presentations by the utility.

The utilities and the state agencies have said that voluntary residential conversion from fuel oil to natural gas home heating is critical for the project to create demand and a market for gas to hit AIDEA’s stated goal of a final “burner tip” price of $15 per thousand cubic, or mcf, of gas.

Conversion is expected to be slow in the first years of the project and increase as gas becomes available to more homes. Depending on the type of boiler system a home has, conversion could cost anywhere from $2,300 to more than $10,000, according to a January 2014 study conducted by the environmental consulting firm Cardno Entrix for the Interior Energy Project.

“I proposed that (AIDEA) simply start a pilot program to create enthusiasm for the market,” Guttenberg said.

While his plan would leave the details to the experts, Guttenberg said, for example, the IEP team could choose 100 Fairbanks homes to retrofit and subsidize the changeover. It would be a way to assure people the state is not “spending hundreds of millions towards more studies, more projects that are never going to happen,” he said.

Doing so would also create an anticipation and enthusiasm amongst Interior residents for a cheaper energy supply when gas finally starts rolling down the Dalton Highway, Guttenberg said.

“Get gas to them, make it a very visible project and get people motivated (and asking) ‘Why don’t I have gas?’” he said.

AIDEA and AEA have responded that they are discussing ways to encourage conversion, according to Guttenberg.

The Cardno Entrix study projects 10 percent of residential customers will convert in the first year of each build out phase. In year two, another 40 percent will make the change to natural gas and by the fifth year gas is available 90 percent of eligible homes will be hooked up to the gas distribution system, the study claims.

Another key to the project is what kind of large commercial or industrial demand there is for gas. Golden Valley Electric Association President and CEO Cory Borgeson has said the utility would purchase up to 2.5 billion cubic feet of gas annually as soon as it is available for power generation. That commitment has shrunk since Golden Valley’s Healy clean coal power plant has become a reality.

The likelihood of finding other large customers to make the project viable is unknown, but AIDEA’s team says it is something they are continually working on.

While a plan like the Interior Energy Project has been discussed for years, it came together at the end of the 2013 session when the Legislature passed $332.5 million in bonds, loans and grants to get North Slope gas to the region in Senate Bill 23.

If Guttenberg’s suggestion of a marketing plan with the easiest gas available, likely trucked Cook Inlet gas, takes shape, another funding source would probably be needed as SB 23 specifies all the funds from the legislation must be used to get North Slope gas south.

A Democrat, Guttenberg said Gov. Sean Parnell could make subsidized conversions a reality if he wanted.

Spending up front to market a product is something done successfully in the private sector every day, he said.

“Act like a normal entity. Act like someone who is trying to create a market for your product,” he said. “Get the enthusiasm going; that’s basically it.”

The fact that Interior’s energy crisis hasn’t yet been solved should be blamed on Alaska’s recent leadership, he said, and is one of the “failings” of the Parnell administration.

“When oil hits $100 and above and you’re in that neighborhood and you’re getting billions of dollars of extra revenue as far as I’m concerned you have an obligation to build an economy,” Guttenberg said.

“You hear from the (Fairbanks) Chamber of Commerce and everybody the one thing holding down development is the cost of energy.”

Read more:

Sunday, July 13, 2014

Producers erase decline for FY 2014

Tim Bradner
Alaska Journal of Commerce

In a dramatic development, North Slope oil producers have essentially erased a long-term decline trend that has existed for all but one year since 1989 when two new oil fields began producing in 2002.

An intensive effort in “workovers” of producing wells, to stimulate production, and drilling of new producing wells in the large producing fields, has hiked production over what was expected by the state Revenue Department.

The estimated daily average for fiscal year 2014, which ended June 30, is 530,939 barrels per day compared with the average of 531,639 barrels per day in fiscal year 2013.

With production through May confirmed for eleven months of fiscal year 2014, and preliminary data from June based on daily production tickets, the estimated decline for the North Slope for the fiscal year is calculated at 0.13 percent, or essentially zero, said John Tichotsky, chief economist in the Department of Revenue. The 2013 fiscal year had a decline of 8.2 percent.

The 0.13 percent decline estimate is the second-best annual performance since 1989. There was a 2.6 percent increase in fiscal year 2002 when the Alpine field operated by ConocoPhillips and North Star field operated by BP began producing.

Passage of a change in the state’s oil production tax in 2013, in Senate Bill 21, is being credited for increased activity on the Slope, but a leading critic of the tax change, State Sen. Bill Wielechowski, D-Anchorage, dismissed the new data.

“While the industry may be successful in slightly increasing production before the referendum vote (to repeal the new tax) in August, the fact is that the long-term projections by the (Gov. Sean) Parnell administration show a 45 percent decline in oil production over the next decade,” Wielechowski wrote in an email.

However, the state’s official long-term production estimates, published annually in November, were put together before the new tax law took effect and do not reflect the level of response shown by the companies recently.

Alaska voters will decide whether to repeal SB 21 on the Aug. 19 primary ballot, with a yes vote to repeal and a no vote to keep it in place.

“The number one statistic that matters most to Alaskans is production, not forecasts or projections. The news that we have ‘stopped the drop’ in our oil production for the first time in more than 10 years is no surprise to those of us who believe creating a competitive investment climate will bring more rigs, more jobs, and more oil to the state.

“Proof of this concept is now out for everyone to see; oil tax reform is working,” said Kara Moriarty, president and CEO of the Alaska Oil and Gas Association. “More production also means more royalties going into the Permanent Fund, as a result of the change. It’s also another compelling reason to vote no on ballot measure 1 on Aug. 19.”

On June 10, in a press release, Wielechowski also said he would drop his opposition to SB 21 if the industry produced one barrel of new production above the 2013 average of 531,000 barrels and it resulted in new revenue.

“If SB 21 produces new oil, even ONE new additional barrel, and this production results in new revenue to the state, we will drop our support for revising oil taxes, Wielechowski said in the June 10 release.

State Sen. Hollis French, D-Anchorage, joined Wielechowski in issuing the release.

The revenue picture will take some time to finalize, but the first estimate shows the producers missed Wielechowski’s challenge by only 701 barrels in the per day average.

State agencies monitor oil production closely because about 90 percent of state revenues come from oil royalties and taxes. The Alaska Oil and Gas Conservation Commission, an independent state regulatory agency, supervises and tests the meters that measure the flow of oil.

The long-term average decline from the North Slope fields has been about 6 percent since 1989. Last December, forecasters in the Department of Revenue, anticipating better performance from producers based on the tax change, estimated that the fiscal year ending June 30 would see a 4.4 percent average decline.

The buildup of production surprised state officials. By March and April it appeared there might even be a slight net increase over last year but June production rates are somewhat down because of maintenance on production facilities. That results in a lower production rate for that month, although the barrels will eventually be produced.

Tichotsky said the figures may look a little better when the official June production numbers come in.

“The production for June and all of 2014 will be officially finalized sometime in the first week of August, when the June production off-take reports come in, and will likely be slightly higher and bring us closer to one-tenth of a percent of a zero decline,” he said.

By comparison, one-tenth of a percent is within the 0.25 percent margin of error range for the meters that measure the oil production.

Tichotsky said state economists Loren Crawford and Tim Harper, in the Revenue Department’s Economic Research Group, compiled the production numbers.

A number of new oil development projects have been announced for the North Slope since mid-2013, when SB 21 passed the Legislature, but it takes time for new projects to be approved by company boards of directors and to secure permits for construction.

ConocoPhillips, one of two major North Slope operators, has three new projects planned that will result in a net addition of 40,000 barrels per day of new Slope production by 2018, according to Scott Jepsen, the company’s vice president for external affairs.

BP Exploration Alaska, which operates the large Prudhoe Bay field, is planning a major development project in the western part of the field that will eventually add 40,000 barrels per day of production, the company has said.

In the short-term, however, both BP and ConocoPhillips have boosted production through more intensive drilling and workovers of existing wells. Both companies have added more drilling rigs and boosted activity levels.

BP’s work on projects to boost well production is up 20 percent over last year, and spending on “production-enhancement” work is up 40 percent, company spokeswoman Dawn Patience said.

Read more:

The evolution of Alaska’s oil taxes

Tim Bradner
Alaska Journal of Commerce

Editor’s note: In this issue, you’ll find a comprehensive look at the issues surrounding the upcoming Aug. 19 election that will decide whether Alaska keeps the oil tax reform bill passed in 2013 or returns to the previous system known as ACES, or Alaska’s Clear and Equitable Share, that was in place from 2007 until the end of 2013. A ‘no’ vote will keep the 2013 tax reform in place while a ‘yes’ vote will revert the state to ACES. The critics of oil tax reform have labeled it a ‘giveaway’ to industry while its supporters have argued that reform was necessary to encourage additional production and make the state competitive with other parts of the world. We hope the information in this special edition of the Alaska Journal of Commerce will help our readers make an informed choice at the poll next month.

How do Alaska’s oil taxes work?

Our state has several ways that we tax the value of oil production. With the upcoming Ballot Proposition 1 vote, most attention is on the state production tax, which was changed by the Legislature in 2013 with Senate Bill 21.

There are two other special state taxes on oil, however. One is a state property tax on oil and gas production facilities and pipelines; it is Alaska’s only state property tax. A second is a special state corporate income tax on oil producers that operates differently than the corporate income tax on non-petroleum corporations operating in Alaska.

Although it is not a tax, royalties from oil and gas production from state-owned lands are also a significant source of income to the state treasury.

The production tax brings in most of the revenue, however. In the state fiscal year concluded June 30, Alaska received an estimated $2.1 billion from the production tax; $464 million from the corporate income tax and $97 million from the state property tax. Another $1.68 billion was paid in royalties.

Altogether, oil revenues pay about 90 percent of the state’s unrestricted general fund revenues

. Production tax is on net revenue

The state production tax is usually referred to as a tax on net revenue of oil produced. From a practical standpoint it applies only on the North Slope, because Cook Inlet oil producers essentially pay no production tax.

What is taxed is really the net value of the oil, which is calculated by deducting production costs from sales revenues. The sales revenues are derived from income received on the West Coast with deductions allowed for tanker costs from Valdez and transportation costs through the Trans-Alaska Pipeline System.

Because no oil is actually bought or sold on the Slope to indicate actual market sales prices, the state uses this method to derive the value of a barrel of oil at the field for tax purposes as well as for royalty cash payments.

Alaska has had a net revenues tax on oil since 2006, which allows production costs to be deducted.

For most of its years as an oil producing state — in Cook Inlet since the 1960s and the North Slope since the 1970s — the state had a “gross revenues” tax, allowing deductions for transportation costs but not production costs.

The change to a net revenues tax — it was first called the Petroleum Profits Tax, or PPT, in 2006 — was a fundamental shift in Alaska’s oil tax policy. It was proposed by former Gov. Frank Murkowski at the urging of economists in the state Revenue Department who had long argued that a net revenues tax would perform better for the state, over the long term, than the gross revenues tax.

That was because the gross revenues tax performed in odd ways as oil prices fluctuated, and sometimes to the disadvantage of the state. In periods of high oil prices, for example, the producers would capture most of the gains while the state would miss out.

However, the gross revenues system also worked to the state’s advantage in periods of low prices because the price dip affected state revenues less than it did the producers’ incomes.

Although there would be benefits and costs of the net revenue system over time, economists argued the net revenues system was better overall because it allowed the state to gain in the “upside,” when oil prices were high, but also to share some of the pain with producers on the downside, when prices were low.

By keeping more revenue flowing to the producers during a price slump it would encourage them to keep drilling to sustain production, the revenue department argued. It was, overall, a more equitable sharing of the benefits and risks, they said.

Murkowski adopted the idea and pressed the new Petroleum Profits Tax, or PPT, on the producers as a bargaining chip in negotiations over a deal on a natural gas pipeline, which were underway in 2005 and 2006.

The new tax was actually a tax increase on the producers because the deal also ended the Economic Limit Factor, a development tax incentive in the former tax that had become obsolete and harmful to the state while it benefitted the producers.

The companies reluctantly accepted the tax increase in return for the state agreeing to certain terms in the gas pipeline deal. The Legislature, in a special session, enacted the tax change and increase but not the pipeline deal, however.

One element introduced into the Petroleum Profits Tax in 2006 was a “progressivity” formula that increased the tax rate as the per-barrel value of oil rose. The increases were relatively mild, however. It was indexed so that the base tax rate, which was set at 22.5 percent, went up 0.2 percent for each dollar increase in the net value of a barrel of oil.

The progressivity index was to double the following year, however.

ACES ascends

In 2007, Gov. Sarah Palin was in the governor’s mansion instead of Frank Murkowski. Palin wanted her own stamp on the state production tax and asked the Department of Revenue for recommendations. As with any new tax, like the PPT, there were tweaks that the Revenue Department considered necessary, and several recommendations were made to the new governor.

Palin also increased the base rate of the tax from 22.5 percent to 25 percent in the revised tax and also lowered the per-barrel value at which the progressivity formula would kick in from $40 per barrel to $30 per barrel.

Palin introduced these proposals in a bill and changed the name of the tax to “Alaska’s Clear and Equitable Share” or ACES, to put her personal stamp on it.

Overall, the impact of her proposals was relatively mild compared with what was to come.

As the ACES bill progressed through the Legislature in 2007, each House and Senate committee wanted to put its mark on the bill. Oil prices were rising at the time, along with fuel prices at the pump, and legislators were getting heat from constituents over energy costs.

Lawmakers responded by increasing the index of the progressivity formula so that the tax rate went up faster — from 0.2 percent to 0.4 percent — as oil values rose, driven by high oil prices.

Those changes would bring in more revenues to the state from the industry’s “windfall” from high oil prices, it was argued. Later, in 2008, some of the higher state revenues were distributed to citizens in the form of a one-time “energy dividend” payment of $1,200.

However, as the ACES bill moved through the Legislature in 2007 it seemed each legislative committee tried to outdo the previous committee in making it “tougher” on the industry. When the ACES bill finally went to the House and Senate floor that year there were even amendments being made — and decided — by floor votes.

ACES in the hole

The effects of the high tax rates were quickly to be felt. Doyon Drilling, one of the state’s major drilling contractors, saw two of its rigs laid off. Drilling activity dropped from 10 rigs working in 2006 to 8 in 2007 and to 6 in 2010. (Drilling has since increased to 17 rigs working this past winter).

Drilling is a key indicator because it is typically the drilling of new production wells that sustains the producing fields. As the drilling slowed, the decline in production continued at a long-term average of 6 percent per year and even increased to 8 percent in some years.

At the time, the North Slope producers were also making major investments in field maintenance, but the amount of capital spent on developing new oil, which is the important number, dropped.

By 2010 and 2011 only 30 cents of every dollar invested by the major producers was spent on activity like drilling, ConocoPhillips Alaska president Trond-Erik Johansen said. The other 70 percent was being spent on maintenance.

Overall capital investment by the companies, including the major maintenance and any new development, was flat. Exploration drilling also dropped. In the winter of 2011 there was only one exploration well drilled on the Slope.

The aggressive progressivity formula in ACES resulted in an effective “total government take” (combined state and federal taxes) on North Slope production of more than 70 percent at times.

It was one of the highest tax regimes of any oil-producing region of the world among those that used tax and royalty systems (some producing nations rely on production-sharing agreements with producers).

Bulging budgets

Defenders of ACES argue that the gush of revenues produced by the tax resulted, during period of high prices, in a buildup of state savings that are now cushioning the deficits in the state budget.

Some of the revenues went into state savings accounts but much of the revenue was also spent in hefty state capital budgets. At the time, Sens. Lyman Hoffman, D-Bethel, and Bert Stedman, R-Sitka, said the big state capital budgets helped cushion the state’s economy when the rest of the nation tipped into sharp recession in 2009.

Hoffman and Stedman co-chaired the Senate Finance Committee during some of those years. However, the availability of the ACES revenue also resulted in substantial increases in the state operating budget, Sen. Pete Kelly, R-Fairbanks, the current Senate Finance co-chair, has observed.

The state’s gain was at the expense of the oil producers, who were largely cut out of the benefits of higher prices. For example, in 2007 when crude oil prices were about $70 per barrel, ConocoPhillips, which reports income for Alaska operations, earned net revenues of about $22 per barrel on its production that year. Meanwhile, the state earned about $27 per barrel (state taxes and royalty combined) on ConocoPhillips’ production.

In 2011, oil prices were about $106 per barrel. ConocoPhillips earned about $27 per barrel, $2 per barrel higher, but the state earned $51 per barrel.

Balancing the take

What’s important about this is how it affects the companies’ long-term projections on pending new investments. The companies know that, over time, there will be cycles of high prices as well as cycles of lower prices, and they need to know that when the high price cycle occurs they can share in the gain along with the state.

The best tax, they say, is one where “upside” gains are split 50-50 between the companies and the state. Senate Bill 21 largely does this, they say.

The split doesn’t work that way on the low-price cycle, however. Both ACES and SB 21 have minimum-price floor tax rates that protect the state’s revenues if prices drop too low. The companies say they are willing to accept this as long as the upside is shared. ACES wouldn’t allow that, however.

As designed, the ACES tax led to declining investment in the North Slope fields in the kinds of activity like drilling that makes new oil. Meanwhile, states with less aggressive tax structures, like North Dakota and Texas, enjoyed huge increases in industry investment over the same period and rapid increases in production.

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Saturday, July 5, 2014

Fifth well on horizon; Furie obtains Kitchen Lights no. 5 permit as gas field development proceeds

By Alan Bailey
Petroleum News

Furie Operating Alaska has obtained a permit to drill a fifth well in the Kitchen Lights unit, in the northern part of the Cook Inlet. In the latter part of the 2013 drilling season the company used its Spartan 151 jack-up drilling rig to start the drilling of the Kitchen Lights unit no. 4 well. Furie’s President Damon Kade has told Petroleum News that his company’s plans for the drilling of both the no. 4 and the no. 5 wells are confidential. However, both wells are clearly exploration wells and, given the timing of the permit application for the no. 5 well, Furie would appear to be planning to at least start the drilling of that well during the current drilling season.

The Kitchen Lights unit is divided into four exploration blocks. In the southern part of the unit, immediately north of the East Foreland region of the Kenai Peninsula, lie the southwest and central blocks. In the middle lies the Corsair block, with the fourth block, the northern block, in the unit’s northeastern sector.

Furie is currently engaged in the development of a gas field, based around the Kitchen Lights unit no. 3 well in the Corsair block. The development involves the installation of a new offshore gas production platform, laying of gas-gathering pipelines from the platform to shore, and the construction of an onshore facility. The platform has been fabricated and is currently being shipped from Texas to the Cook Inlet. The Kitchen Lights no. 1 and no. 2 wells are also located in the Corsair block.

The Kitchen Lights no. 4 well is located in the Northern block. And, based on location information included with the new drilling permit, the no. 5 well location would appear to be towards the western side of the central block, about halfway down the block.

The sequence of drilling appears consistent with requirements in Furie’s Kitchen Lights exploration plan, stating that the company must drill wells in several exploration blocks within the Kitchen Lights unit.

Exploration blocks

The locations of the exploration blocks, and the exploration prospects that each block encapsulates, relate to the subsurface geologic structures that characterize the Cook Inlet basin. Essentially, the strata that typically host the Cook Inlet oil and gas fields have been deformed into a series of north-north-east trending folds, with hydrocarbon resources tending to become trapped in the crests of the folds. Each fold forms an elongated dome-like structure, generally bounded by geologic faults. The folds form sets, with the folds within a set lined up end-to-end along a north-north-east trend line.

The Corsair block, in which Furie is developing its new gas field, contains a structure on a fold trend that lines up with the North Cook Inlet gas field to the north and the Kenai and Cannery Loop gas fields to the south. Shell, Phillips and ARCO, between them, drilled five wells in the prospect between 1962 and 1993. The wells all had gas show, with some also testing small quantities of oil.

None of the other prospects within the Northern Lights unit have seen previous drilling.

The northern block corresponds to what used to be called the Northern Lights prospect and lies on the same structural trend as the Corsair block. The Northern Lights prospect has in the past been viewed as an oil opportunity related to a known oil pool under the North Cook Inlet field.

The central block corresponds approximately to what used to be called the East Kitchen Lights prospect, a prospect lying on that same structural trend as Corsair and the northern block.

The southwestern block corresponds to what was called the Kitchen prospect, a structure on the east side of the fold structure that holds the Middle Ground Shoal oil field.

- A copyrighted oil and gas lease map from Mapmakers Alaska was a research tool used in preparing this story.

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Many new opportunities; Recent seismic data identifies more drilling targets in the aging Kuparuk field

By Alan Bailey
Petroleum News

Recent 3-D seismic surveys in the Kuparuk River field on Alaska’s North Slope are enabling the identification of new drilling leads in the field, according to field operator ConocoPhillips’ latest Kuparuk plan of development that the company has submitted to the Alaska Department of Natural Resources. A survey conducted in 2005 has enabled the discovery of a number of drilling opportunities, including sidetrack wells using coiled tubing drilling, sidetracks using conventional rotary drilling, and the drilling of new wells, the plan says.

The results of another survey, conducted over 220 square miles of the western part of the Kuparuk River unit in 2011, are still being interpreted, with the results being integrated into work programs and the identification of further drilling opportunities. And in 2013 ConocoPhillips merged this survey with another survey in the southwestern part of the unit, to allow complete coverage of the area of the Shark Tooth prospect that the company is currently working on, the plan says.

Coiled tubing drilling, a key drilling technique in the Kuparuk field, involves the use of a continuous length of small-diameter, flexible drill pipe, with a motor-driven drill bit. The flexible drill pipe is drilled out from the side of an existing well bore, to form a sidetrack well that can snake its way through packages of oil-bearing reservoir sands.

The large portfolio of potential coiled tubing wells has resulted in the commissioning and contracting of a state-of-the-art specialized coiled tubing Arctic drilling rig that has been in continuous use since May 2009, the plan says.

A huge field

As one of the largest producing oil fields in North America, the Kuparuk River field has been delivering oil since the early 1980s. But, as the amount of oil remaining in the ground declines, ConocoPhillips is having to use high-tech drilling and oil recovery techniques to extract further oil from the field’s challenging, compartmentalized reservoir rocks. In May Trond-Erik Johansen, the company’s Alaska president, told the Anchorage Chamber of Commerce that 3.75 billion barrels of conventional oil remain in the field, and that there are a further 15 billion barrels of heavy oil in the Kuparuk River unit.

In 2013 field production averaged 85,700 barrels of oil per day, the plan of development says. During that year ConocoPhillips completed a 14-well coiled-tubing-drilling program that generated a peak rate of 4,520 barrels per day of incremental oil. The company also completed one conventional well, the plan says.

In 2013 the field had 466 production wells and 351 injection wells in 44 drill sites.

ConocoPhillips anticipates 13 to 17 coiled tubing sidetrack projects and eight new conventional rotary wells in 2014, the plan says.

Enhanced oil recovery

Maximizing oil recovery from the aging field involves the effective management of various techniques for enhanced oil recovery, as well as delineating areas of the field with oil accumulations that can viably be developed and then drilling appropriate development wells.

At the core of the oil recovery strategy comes waterflood, the injection of seawater and produced water into the field reservoir to sweep oil from the reservoir rock. But the alternation of waterflood with the injection of a material known as miscible injectant, a mixture of natural gas and natural gas liquids, has become the procedure of choice for enhanced oil recovery. Essentially, the miscible injectant acts as a solvent, leaching the oil from the rock pores, while the water sweeps the oil towards production wells.

The technique, referred to as water-alternating-gas, or WAG, can involve the use of either miscible injectant or immiscible dry gas. And, as the field has evolved, some drill sites have stopped using miscible injectant, and some have been converted to water injection only, the plan says. ConocoPhillips has been piloting the use of injected dry gas to retrieve from the reservoir some of the natural gas liquids that were previously injected as miscible injectant.

ConocoPhillips is also evaluating the potential use of a technique called alkali surfactant polymer, or ASP, for mobilizing oil in one of the Kuparuk sands, the plan says.

Artificial lift

One benefit of using miscible injectant for enhanced oil recovery is the manner in which the injectant flowing towards production wells assists in “artificial lift,” a procedure whereby oil is driven up a production well by some artificial means, rather than just being forced to the surface by the reservoir pressure. Gas lift, a technique that involves flowing gas into a production well, is the most common artificial lift technique used in the Kuparuk field, the plan says. But the gas lift system cannot by itself drive oil all the way to the surface in many wells, given limitations on gas pressure and the fact that some wells are now producing fluids containing as much as 95 percent water, the plan says.

Gas needs

Natural gas is clearly a key material for use in oil production at Kuparuk, and is also used as a fuel for the field facilities. In the past, gas production from the field has exceeded fuel requirements, thus enabling the use of surplus gas for WAG operations, the plan says. With insufficient natural gas liquids to meet miscible injectant demand, Kuparuk has for several years been importing natural gas liquids from the neighboring Prudhoe Bay field through a pipeline called the Oliktok pipeline.

But gas production at Kuparuk is declining. So, with fuel gas being critical to field operations, ConocoPhillips has been moving ahead with a plan to convert the Oliktok pipeline for shipping gas rather than natural gas liquids from the Prudhoe Bay field. The import of natural gas liquids from Prudhoe Bay is expected to end in 2014, the plan says. As a consequence, the plan assumes that large-scale WAG with miscible injectant will also stop before the end of 2014. After that time, miscible gas injection will continue at just four drill sites, using natural gas liquids produced from the Kuparuk field, the plan says.

Because the gas from Prudhoe Bay contains 10 to 12 percent carbon dioxide and could, therefore, cause corrosion in the Kuparuk production system, this gas will simply be used as fuel gas, and will not be injected into the Kuparuk field reservoir, the plan says. Then, with indigenous Kuparuk gas that would otherwise have been used as fuel becoming available, ConocoPhillips plans to commence a full-field “lean gas chase,” using injected dry gas to recover some of the natural gas liquids trapped in the reservoir rocks, and to enhance the artificial lift in wells that produce high volumes of water.

Other opportunities

In addition to maximizing oil recovery within the traditional reservoirs of the Kuparuk field, ConocoPhillips sees potential for exploration and appraisal leads identified from seismic surveys within the Kuparuk River unit, the plan says. The company has been moving forward with one of these opportunities, the Shark Tooth prospect, having drilled a well in the prospect in January 2012. Production results are also being evaluated, following a perforation and hydraulic fracturing pilot test in the Cretaceous Moraine interval, an oil reservoir in the Brookian rock sequence above the reservoir rocks of the Kuparuk field, the plan says.

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